1. Field of the Invention
The present invention generally relates to interconnected power transmission networks and more particularly to a system for displaying the dynamic on-line operating conditions of an interconnected power transmission network.
2. Description of the Prior Art
An electric power network is comprised of three systems: generation, transmission and distribution. In order to deliver electric power across vast distances, the voltage developed by a generation system must be "stepped up" by transformers to a very high voltage for transport to customers. This high voltage is then delivered to a customer's area on a transmission system. Once in the customer's area, the high voltage is "stepped down" by transformers to a lower voltage level then delivered to local customers through a distribution system. Generated voltage is stepped up to very high levels to prevent the loss of power during transmission.
In order to maintain the high voltage level during transmission, maintenance areas or "busses" are installed along the transmission system, where the voltage entering a buss is the same magnitude as the voltage leaving the buss. A "substation" is not only a maintenance area, but is also used to step down the transmission voltage for distribution to customers.
In the operation of an electric power network, and especially in an interconnected power transmission network extending over a large geographic area, system operators, the personnel who control these systems are occasionally confronted with disturbances or abnormal conditions which defy analysis in the time available to avoid a major brown out, or complete power outage over an extended portion of the network. This is due to the fact that the amount of detailed information available to the system operator is beyond one's ability to comprehend when a serious emergency occurs. As a result, massive system outages can occur beyond those caused by the initial failure.
Individual power systems are interconnected with neighboring power systems for improved security and economic reasons. The security benefits arise from the fact that interconnected companies have many more generators on the line than a single company, and the greater dispersion of generation will improve the likelihood that a severe contingency generally will not lead to as critical a condition as would occur for the individual companies. The economic value of interconnections is found in the economy of scale that pervades most all utility operating costs.
To secure these interconnection benefits, each utility should operate according to a combined or coordinated system plan for joint and cooperative operation. This requires each company's operating center to process more information on a continuing basis than as an independently operated utility. Thus, the burden on a system operator is increased as more data becomes available when an emergency does develop. Alternately, if individual system operators are not privy to adjacent system operating data, a calamity can overtake the combined systems before a problem is fully recognized by any one of the operators.
These effects result in a measure of insecurity, offsetting some of the advantage noted above for joint or interconnected operation. There is an undefined limit to the size of an interconnected system based not on conventional network loading and voltage constraints, but on this limitation of processing massive amounts of operating data in a timely manner. The occasional security failure of the western power "doughnut" is possibly due to this fact.
The information which a system operator has to work with consists of the magnitude of quantities such as amperage from key locations throughout the system. These values are telemetered to the system operator over reliable communication circuits where they are displayed by standard large faced numerical meters, or video monitor. Some of the meters may be located at the system operator's desk and some on the mimic board (a diagram replicating the lines, transformers and other components of the system) at the same location as the source of the derived signal in the power network. The mimic board will also have other information displayed by different colored lights, also located comparable to the source of the information in the network. The color of these lights have various meanings regarding the condition of various components in the network, such as temperature of transformers, position (open or closed) of circuit breakers, disconnect switches and the like. Equipment which is out of service for maintenance or construction reasons also will be indicated on the mimic board.
The system operator also has telephone communications with key field operating personnel and uses information obtained from the operating personnel to augment telemetered information for manually keeping the system in an adequate security position, and keeping his mimic board up to date on the status of equipment outages and any other equipment that does not have telemetry facilities in service. While each company's system operator has the condition of all interconnection tie lines to neighboring utilities available to him, an operator generally will not have full details of the internal conditions of neighboring utilities available, except by telephone communications. In the panic of a power system disturbance, it may be an considered an abnormal demand upon a system operator to drop what the operator is doing in order to phone neighboring utilities to keep them informed.
It is generally not feasible to reduce a system operator's work load by using more operating personnel because of the network inter-relations, which require that each operator comprehend the entire system to carry out assigned responsibilities. It is therefore evident that an entirely new method of presenting system conditions is needed if the utilities, in their continued growth, are to provide the quality of service required by consumers.
U.S. Pat. No. 5,594,659 discloses a method for performing a voltage stability security assessment for a region of an electric power transmission system having a plurality of buses and a plurality of sources of reactive reserves coupled thereto. The plurality of buses are grouped into a plurality of voltage control areas such that each of the buses within each voltage control area has a substantially similar reactive margin and voltage at the minimum of the corresponding reactive power versus voltage relationship. A corresponding reactive reserve basin is determined for each of at least one of the voltage control areas. Comprising at least one of the sources of reactive reserves selected in dependence upon a measure of the reactive reserves depleted at a predetermined operating point of the electric power transmission system. A single contingency analysis is performed by computing a corresponding quantity for each reactive reserve basin in response to each of a plurality of single contingencies, representative of a reduction in the reactive reserves within the reactive reserve basin. A multiple contingency analysis is performed for each reactive reserve basin using the single contingencies whose corresponding quantity exceeds a predetermined threshold.
U.S. Pat. No. 5,566,085 shows a transient or voltage stability transfer limit calculated for a power network having at least two independent generators supplying a common load through separate transmission lines, steady state values for variable characteristic electrical parameters of variable elements of the network are determined based on particular values for power transferred by the transmission lines. Static values for passive characteristic electrical parameters of passive conductive elements of the network are determined. A contingency resulting in a sudden change of at least one of the variable electrical parameters and the passive electrical parameters is selected. A post contingency steady state value for a voltage at one of the buses is calculated. A voltage over time during a transition period at the bus is calculated, the transition period extending in time from a start of the contingency through a discontinuity during which the voltage is abnormally altered and recovery during which the voltage will tend toward a steady state terminal value. Using two energy values from two power values, a transfer limit estimate for the transmission line is obtained as being an asymptote of the energy values, the energy values being an inverse function of the stability limit less the power value.
U.S. Pat. No. 5,539,651 teaches a system and method for determining the effects of linear and nonlinear loads on electrical power systems. The invention utilizes stored load characteristic data in terms of current spectra at predefined voltage values and network impedances to determine the voltage drop between an electrical substation bus and an electrical load bus. The actual load voltage is determined by an iteration technique which takes the difference between a collected substation voltage and the voltage drop and compares the result Of the difference to an estimated load voltage. For each iteration the estimated load voltage is re-estimated until the difference result equals the estimated voltage, thereby determining the actual load voltage. Knowing the actual load voltage, permits determination of actual current and power values which are compared to collected substation current and power values. If the values are equal, the effects of the harmonics are known. If the values are not equal, load composition data is adjusted and the system repeats the above until the values are equal.
U.S. Pat. Nos. 5,506,789 and 5,512,832 relates to a method and apparatus are provided for detecting an arcing fault on a power line carrying a load current. The apparatus monitors, compiles and analyzes sample parameters taken from successive cycles of the power line load signal indicative of power flow and possible fault events on the line, such as voltage or load current. The analyzed sample parameter is then used to determine a normal parameter corresponding to a normal load pattern for the line.
The normal load parameter is extracted from the compiled sample parameter data, and the resulting difference signal waveform has a magnitude value which changes in amplitude corresponding to the load-extracted data which is used to determine whether a fault exists on the power line.
U.S. Pat. No. 5,479,358 shows a energy supply system including an energy demand plan for predicting an energy demand on the basis of past cases of energy supply and for formulating an energy demand plan with respect to time. The variation of the future energy demand is predicted and energy which accommodates the determined variation can be prepared.
U.S. Pat. No. 5,406,495 teaches a monitoring and control system to invention provide a distributed intelligence, data acquisition and control system which collects and analyzes large amounts of data representing power usage from a power distribution substation. Using a Discrete Fourier Transform, the system provides accurate tracking of the primary frequency of the voltage and current waveforms in the power equipment, and determines the relative phase between the voltage and current waveforms. The system provides real time monitoring of power usage and real time control of various functions in the substation.
U.S. Pat. No. 5,237,511 discloses a improved distribution automation remote terminal unit which directly connects to a distribution feeder. The distribution automation remote terminal unit is directly connected to voltage and current sensors on the feeder to sense the presence of signals on the distribution feeder. The remote terminal unit includes the first transformer interconnected to the potential sensors to produce a potential signal of reduced peak-to-peak voltage corresponding in phase to the AC potential waveform on the distribution feeder. A second transformer is directly coupled to the current sensor for producing a current signal of reduced peak-to-peak voltage corresponding in phase to only the AC current waveform on the distribution feeder. The reduced peak-to-peak voltage signals are delivered into a multiplexer and are sampled a predetermined number of times. The sampled analog voltage is then digitized by a digital to analog converter and delivered into a digital signal processor. Waveform parameters are determined. A microcontroller then accesses the waveform parameters to determine information such as the operation of upstream and downstream devices on the distribution feeder. This information is selectively transmitted to a remote master station over a communications link.
U.S. Pat. No. 233,538 shows a circuit monitoring system for a distributed power network employs waveform capturing techniques for efficient and highly accurate monitoring, including a plurality of circuit monitors and a control station, which is coupled to each of the circuit monitors via a multi-drop communications link. Each of the circuit monitors is disposed adjacent an associated one of the branches in the network for sensing power parameters in the branches and for generating and transmitting data representing the power parameters to the control station. The control station is used for generating monitoring commands to each of the circuit monitors to provide the system with full system control and evaluation capability. The system is capable of simultaneously sensing the waveform at each branch and sampling the waveforms for a predetermined number of sample points over a integral number of cycles so as to provide an efficient yet accurate implementation.
U.S. Pat. No. 4,589,075 relates to a load management system for a power network which both addresses remote load controllers and acquires load data through a retransmission network. A central controller processes power load a data and generates digital messages which address loads and command the selective connection and disconnection Of loads. The central controller transmits the generated digital messages via radio frequency transmissions. Programmable retransmission stations receive, decode and directionally retransmit the digital messages. Addressable remote load controllers receive and decode transmitted digital messages and operate to connect and disconnect loads in response to command messages received by the addressed load controllers. Addressable data acquisition units sense loads at points in the power network and operate to generate digital load data messages. Retransmission stations receive load data messages from the addressable data acquisition units and retransmit load data messages through the retransmission network to the central controller. Yet other digital messages are translated into paging signals and disseminated to remote paging units.